Bankability Concerns Over New Generation of Indonesian Power Purchase Agreements

Bankability Concerns Over New Generation of Indonesian Power Purchase
Agreements

The Indonesian power sector has to date been the most successful of the
infrastructure sectors in attracting private sector investment, and debt
financing from both international and domestic lenders. The State power
utility, PT PLN (Persero), has since the very early private sector power
generation projects of the 1990s developed a robust and bankable Power
Purchase Agreement (PPA) model for large scale power projects. Whilst there
have been the inevitable tweaks to the PPA model over the past 20 years
(coming from both the PLN side of the negotiation table as well as the
developer/lender side), the model for large scale power projects remains
today a solid one, and one that is able to mobilise private sector equity
and debt funding. Recent flagship projects that demonstrate the success of
the current PPA model include the Central Java 2x1000MW project, the Sarulla
Geothermal Project and many others.

However the Ministry of Energy and Mineral Resources on 19 January 2017
issued Regulation No. 10/2017 on Principles of Power Purchase Agreements
(MEMR Reg. 10), which, for the first time in any material way, seeks to
impose certain requirements as to what provisions must be built into PPAs in
the power sector.

Other power sector regulations have, from time to time, touched lightly on
certain aspects of the PPAs (e.g., the mini-hydro regulations provide that
if the developer fails to complete construction of the project within the
required timeframe, the tariff under the PPA should be subjected to a
discount as a form of penalty), but the key bankability and risk allocation
points have been left to negotiation between PLN and the developers (and
lenders). However with the passing of MEMR Reg. 10, PLN's freedom to
negotiate terms has been curtailed.

What power projects are covered by MEMR Reg. 10?

The regulation applies to all power projects, including geothermal, biomass
and hydropower plants.

However, the regulation does not apply to intermittent power projects (i.e.,
wind and solar, regardless of size), mini-hydro power plants (below 10MW),
biogas power plants and waste-to-energy power plants. These categories of
power plants will be subject to their own specific regulations.

Additionally, the transitional provisions of the regulation provide that
these new PPA requirements will not apply to PLN procurement processes where
bid closing has already occurred, where PLN has signed letters of intent
with developers, or where the PPA has already been signed or where there is
any amendment to an existing PPA.

For geothermal projects where the auction process to award the geothermal
concession has already been completed, or projects where the winner has been
declared, or where the PPA has been signed, they too will not be subject to
the regulation.

For all relevant projects where the procurement processes are ongoing and
bid closing has not occurred, the new requirements must be complied with.
Accordingly, we suspect that PLN will soon be issuing extension notices for
ongoing bid processes, to give PLN enough time to adapt the model PPAs
contained within those bid packages to the requirements of MEMR Reg. 10.

What are the controversial changes under MEMR Reg. 10?

MEMR Reg. 10 introduces a number of new mandatory concepts which are
certainly likely to give rise to concerns with developers and their lenders:

All projects must be on a Build-Own-Operate-Transfer (BOOT) model

Whilst coal projects have been traditionally awarded by PLN on a BOOT basis,
with ownership of the projects having to be transferred to PLN at the end of
the term of the PPA, other projects such as geothermal and hydro have been
awarded on a BOO basis (with the developer retaining ownership of the
project at the end of the concession, giving rise to the possibility of
negotiating a renewal PPA or extension with PLN if the design life of the
power plant permits). Accordingly, with this mandated BOOT model, all
potential "upside" for developers has been taken off the table, and all
projects will need to be transferred to PLN for a nominal amount at the end
of the term of the PPA.

Where PLN is unable to evacuate the power from the power plant due to force
majeure affecting PLN, PLN is relieved of its payment obligations This is a
major bankability concern. As the PPAs are largely based on an availability
concept (i.e., the generator's job is to be available for PLN to take the
power if PLN wishes to do so), the early generations of PPAs provided that
if the power generator was available, yet PLN was unable to evacuate the
power for any reason (including due to force majeure affecting PLN), then
the generator was nevertheless paid in full for its availability. In more
recent years, PLN has negotiated a grace period into the PPAs - where, for
instance, if the PLN grid is damaged due to natural force majeure events,
PLN has a maximum 14-day period to rectify the damage (during which PLN is
under no obligation to pay the generator for its availability). It is only
if the grid is not repaired within this 14-day period that PLN must start
paying the generator availability payments. So in this respect, PLN has in
recent years sought to have the developers share the risk of PLN force
majeure events - and developers and lenders have factored this risk into
their financial models and been able to accept this risk sharing. However,
MEMR Reg. 10 indicates that PLN will not be obliged to pay deemed dispatch
if disruption in the PLN grid is caused by force majeure events. Although
Reg. 10 allows the PPA term to be extended in a force majeure event, this
will not fully address lenders' concerns due to the revenue loss impact on
the ability to service the debt. This latest change pushes the entire PLN
force majeure risk onto developers, with developers having no way to manage
or mitigate that risk. Insurance coverage for business interruption is
typically tied to a casualty event affecting the generator's plant and
equipment (not a casualty event affecting PLN's plant and equipment). So
this gap in the risk allocation (and the lack of tools available for
developers to plug the gap) raises large concerns over bankability.

Government force majeure risk being shifted to the developers MEMR Reg. 10
seeks to push responsibility for certain Government force majeure events
onto the developers. One of the fundamental principles of proper risk
allocation is that risk should be allocated to the party best able to manage
and mitigate the risk.

In the context of a PPA, the only two parties to the agreement are a
private sector developer, and a State-owned utility. Accordingly, the
traditional risk allocation is that the State-owned entity should take
responsibility for actions of the State. On this basis, the PPA models used
in Indonesia to date have largely provided that:

in the event of changes in laws or adverse Government action/inaction, the
cost impacts to developers are passed on to PLN as a tariff increase, and
any revenue loss (due to the plant having to shut down) are passed on to PLN
as deemed dispatch payments; and

where there is a prolonged stoppage of the project due to Government
action/inaction (e.g., 180 days continuously), the developer has the right
to terminate the PPA, and PLN must purchase the project from the developer
for an amount equal to outstanding project debt plus lost future equity
returns
However, Article 8 of MEMR Reg. 10 now provides that both PLN and the
developers will take responsibility for Government force majeure events.

Government force majeure is defined in the regulation as "changes in
policies or regulations" (and therefore appears to capture changes in law),
although somewhat confusingly, the same term is used elsewhere in the
regulation to mean only "changes in government policy" (and not changes in
law). Aside from change in laws and policies, the other form of "government
force majeure" typically captured by the PPAs is the unjustified action or
inaction of Government (e.g., delays in issuing permits and approvals and
revocation of licences without cause). Accordingly, following the strict
reading of MEMR Reg. 10, it is still permissible for PLN (as it
traditionally has done) to take responsibility for these unjustified actions
or inactions of Government; however in the case of changes in laws and
policies, the regulation appears to require both PLN and the developer to
bear that risk, with the PPA to further detail how that risk is allocated.
It may be then that PLN seeks to build some form of grace period, or cost
buffer, into the effects of changes in laws and regulations. For example:

In the event of a change in law or regulation that has a cost impact on the
developer (where that cost impact exceeds X% of the tariff), the tariff will
be adjusted
In the event of a change in law or regulation that causes a shutdown of the
power plant, PLN will pay deemed dispatch payments only if the effects of
such event have not been rectified within X days after the occurrence of the
change in law

However, Article 28 of MEMR Reg. 10 also deals with allocation of risk for
changes in laws and changes in government policy. It provides that:

where a change in law results in a higher cost impact to the developer, the
tariff will be adjusted to compensate; and
where a change in policy causes the power plant to stop operation, then both
PLN and the developer are released from their obligations.

The treatment of change in law reflects the risk allocation treatment under
the current generation of PPAs. However, the treatment of change in policies
would appear to conflict with Article 8 - which appears to allow for a
sharing of the risk of changes in government policy (as opposed to simply
releasing PLN from its obligations). One reading of Article 28 which would
result in it being consistent with Article 8 is that Article 8 applies to
temporary shutdowns due to changes in government policy (e.g., if the plant
is shut down for one month, then PLN does not need to pay deemed dispatch
payments for the first 14 days, but thereafter has to start making deemed
dispatch payments) whereas Article 28 applies to prolonged government events
(e.g., if a government change in policy results in the plant being shut down
for longer than 180 days, then the PPA can be terminated). The intent of
Article 28 does at least appear to make clear that where the PPA is
terminated due to a government change in policy, then PLN has no obligation
to buy out the project.

So whilst the regulation appears to continue to give PLN freedom to (i)
cover the cost increase and plant downtime consequences of unjustified
Government actions or inactions, and (ii) cover the cost increase
implications of changes in law, the position in relation to the loss of
revenue caused by plant downtime due to changes in law and changes in
government policy is somewhat unclear.

Statements made by the Government at public launch of MEMR Reg. 10 held on 2
February 2017 suggest that the Government's intention with respect to
Article 28 was not to change the long-standing risk allocation that has
existed under the current PPA model related to the compensation for changes
in Government policy, but instead was to confirm that a power generator had
the comfort of knowing it would be relieved from any liability in the event
of such changes in Government policy. However the text of the regulation
itself does appear to fundamentally change the risk allocation on this point
- making it clear that PLN is similarly relieved from all obligations (which
would include obligations to buy out the project) if such changes in
Government policy occurred leading to a shutdown of the project.

Take or pay commitment from PLN is limited to the debt servicing period

For the PPA models to date, PLN has committed to a take-or-pay commitment
(or guaranteed minimum availability payment) for the entire life of the PPA.
This of course gives comfort to lenders that there will be sufficient
revenues to meet debt service throughout the life of the PPA, but also gives
comfort to the developers that they will see the target return on their
equity investment. MEMR Reg. 10 states that the take-or-pay period within
the PPA is for a "certain period" (i.e., something less than the full term
of the PPA), and goes on to clarify that the "certain period" is determined
by "considering" the repayment period for the financing. So this indicates
that PLN may only be committed to a take-and-pay concept for the debt period
(to ensure lenders are covered), whilst developers will then take the risk
on whether or not PLN dispatches the plant after the debt is repaid.

This take-or-pay model is not entirely new. On a number of the larger
hydropower PPAs, the take-or-pay commitment of PLN is structured such that
it only applies during a presumed debt service period (e.g., for the first
15 years of a 30-year hydro PPA), and following the debt service period, the
PPA is a "take-and-pay" concept (i.e., the developers are only paid if PLN
chooses to dispatch the plant). So in these projects, the sponsors have had
to take a leap of faith that at the end of 15 years, the hydro plant should
be positioned well in the merit order dispatch list, and therefore have a
degree of comfort that despite the lack of any take-or-pay commitment from
PLN, PLN will nevertheless dispatch the plant due to the cheap tariff.

So whilst nothing relating to this issue is going to give lenders any cause
for concern (because the take-or-pay will cover the debt servicing period),
it will require developers to consider whether they are willing to risk
their equity returns on a discretion of PLN whether to dispatch the plant or
not.

Again, at the public launch of the regulation held on 2 February 2017, the
Government commented that all the regulation required was that in
determining the take-or-pay period to apply under the PPA, "consideration"
be given to the debt service period, and that PLN was still free to agree to
provide the take-or-pay commitment for the full term of the PPA. Accordingly
it will be interesting to see what interpretation is given to aspect of the
regulation in the future PPA negotiations.

New performance penalties for failing to meet ramp rates The existing
generation of PPAs typically only penalize developers for failing to meet
the availability targets - i.e., if the availability target (e.g., 80%) is
not met (e.g. actual performance was only 78%), then PLN will only pay the
developer for the 78% of actual availability, and will penalize the
developer a further 2% for the 2% shortfall between the guaranteed
availability and the actual availability. So the developer would receive net
76% for that month. In the most recent base-load PPAs, PLN has sought to
introduce penalties for failing to meet reactive power requirements, as well
as failing to comply with frequency requirements. MEMR Reg. 10 also now
requires the PPA to have a penalty regime for failing to meet ramp up and
ramp down instructions from PLN dispatch centres.

Embedded restrictions on selling shares in the power generation company
PLN's PPAs (and related Sponsor Agreements) have typically imposed
requirements on the project sponsors to maintain ownership of a certain
percentage of shares in the power generator until the project's commercial
operation date (and often for a period 5 years following the commercial
operation date). MEMR Reg. 10 now embeds certain shareholding retention
obligations - prohibiting the transfer of ownership in power generators
prior to the plant achieving commercial operation. What is not entirely
clear is whether a transfer of shares between the founding sponsors of the
project is permitted (e.g., if Company A and Company B are the two founding
50%:50% sponsors of the project, but then Company B is unable to fund cost
overruns etc. and Company A steps in to fund such that Company B is diluted
to 40% and Company A increases to 60%). We believe that because the
ownership of the power generator has not changed (i.e., it is still
collectively owned by the founding sponsors), such flexibility should be
permitted under the PPA without breaching the restriction.

After commercial operation, the transfer of shares in the power generator is
only permitted with the approval of PLN (and must be reported to the
Government). In the existing generation of PPAs, there is generally full
freedom of the sponsors to sell their shares in the power generator after
the fifth anniversary of commercial operation. We do believe that there is
flexibility in the wording of the regulation to allow for a "pre-approval"
mechanism to be built into the PPA to deal with these changes of
shareholding - for example, if a sponsor wishes to sell, the sponsor should
offer the shares to PLN, and if PLN chooses not to exercise its right to buy
those shares, the sponsor is free to sell the shares to a third party (at a
price not less than that offered to PLN) and PLN is deemed to have approved
such sale.

A transfer from a sponsor to its (at least) 90%-owned affiliate entity is
permitted (therefore giving sponsors the flexibility to structure their
ownership of the power generator to meet their internal corporate and tax
requirements).

Conclusion

Clearly the broad principles set out in MEMR Reg. 10 will need to be
translated by PLN and developers into detailed contractual provisions in the
PPAs themselves. The Government has indicated in its public statements on
the regulation that the main aim of the regulation was not to impose any
changes to the existing PPA model used by PLN, with the exception of making
a BOOT model compulsory for all the power projects falling within the scope
of the regulation. The wording of the regulation however appears to have
much further reach.

Whilst some of these broad principles do ring alarm bells in terms of the
future bankability of the Indonesian PPA model, it is hoped that the
flexibility given by "the devil being in the details" can be used to ensure
that this new generation of PPA is still a model on which, like the PPA
generations that preceded it, private sector investors and developers are
willing to invest the billions of US dollars needed to achieve Indonesia's
electrification goals.

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John Diecker
APT Consulting Group Co., Ltd.

www.aptthailand.com